ML17347A521

Technical Bases Revisions Updated Through November 2017

ML17347A521
Person / Time
Site:	Summer
Issue date:	12/12/2017
From:	Lippard G SCANA Corp, South Carolina Electric & Gas Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML17347A521 (14)

Text

George Lippard Vice President, Nuclear Operations 803.345.4810 December 12, 2017 A SCANA COMPANY U. S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555

Subject:

VIRGIL C. SUMMER NUCLEAR STATION (VCSNS) UNIT 1 DOCKET NO. 50-395 OPERATING LICENSE NO. NPF-12 TECHNICAL SPECIFICATION BASES REVISIONS UPDATED THROUGH NOVEMBER 2017 In accordance with VCSNS Unit 1 Technical Specifications (TS) 6.8.4.L4, South Carolina Electric & Gas Company, acting for itself and as agent for the South Carolina Public Service Authority, submits revisions to the TS Bases.

This update includes changes to the TS Bases since the previous submittal in January 2017.

The enclosed changes revised by Bases Revision Notices (BRN)17-002 and BRN 17-004 were implemented under the provision of 10 CFR 50.59. Amendments 207 and 209 also revised TS Bases in accordance with 10 CFR 50.90. Changes are annotated by vertical revision bars and the BRN number or the amendment number at the bottom of the page.

If you have any questions or require additional information, please contact Michael Moore at (803) 345-4752.

Very truly yours, WCM/GL/hk Attachment I: Summary of Bases Changes Attachment II: Technical Specification Bases Revisions Updated Through November 2017 c:

K. B. Marsh S. A. Byrne J. B. Archie N. S. Cams J. H. Hamilton G. J. Lindamood W. M. Cherry C. Haney S. A. Williams NRC Resident Inspector K. M. Sutton NSRC RTS (RR 8925, LTD 338)

File (813.20)

PRSF (RC-17-0139)

V. C. Summer Nuclear Station

• P. 0. Box 88

• Jenkinsville, South Carolina

• 29065

• F (803) 941-9776

• www.sceg.com

Document Control Desk Attachment I RR 8925 RC-17-0139 Page 1 of 3

SUMMARY

OF BASES CHANGES TS Amendment No. 207 Description of Change: Changes to the Bases for Technical Specification (TS) 3/4.5.4, "Refueling Water Storage Tank" (RWST), were submitted and previously approved under License Amendment No. 207, (ML16348A200). The amendment revised TS Bases 3.5.4 to reflect that the information in Limiting Condition for Operation (LCO) Note 3.5.4 was no longer applicable after implementation of engineering change ECR-50879, Spent Fuel (SF) Purification Loop Modification.

Reason and Basis for Change: The paragraph in TS Bases 3/4.5.4 regarding administrative controls to align the safety-related RWST piping to non-safety SF Purification piping needed to be updated to reflect current system design and operation after implementation of engineering change ECR-50879. The change to TS LCO 3.5.4, "Refueling Water Storage Tank", deleted an expired Note TS LOC 3.5.4 that permitted connection of the RWST to non-safety piping for periodic surveillance testing and water filtration under station administrative controls.

BRN No.17-002 Description of Change: TS Bases 3/4.7.1.2, "Emergency Feedwater System," stated "Each emergency feedwater pump is capable of delivering a total feedwater flow of 380 gpm at a pressure of 1211 psig to the entrance of two out of three steam generators." The TS Bases was changed to read "Any two emergency feedwater pumps combined are capable of delivering a total feedwater flow of 380 gpm at a pressure of 1211 psig to the entrance of two out of three intact steam generators following a Main Feedwater Line Break event, while passively limiting the flow to the faulted steam generator. Automatic isolation of the faulted steam generator is not necessary to achieve this flow to the intact steam generators. The 380 gpm to the intact steam generators is sufficient to prevent over pressurization of the RCS and also to prevent the water in RCS hot leg from reaching a saturated condition."

TS Bases 3/4.7.1.2 also stated "The total head criteria of 3800 feet for the motor driven emergency feedwater (MDEFW) pumps and 3140 feet for the turbine driven EFW pump includes margin that allows for a maximum EFW flow control valve leakage of 5 gpm for any one of 6 EFW flow control valves." This was changed to read "The minimum required pump head for the turbine driven (TD) and motor driven (MD) pumps are controlled in accordance with the Inservice Testing Program as required by Specification 4.0.5. These minimum pump performance requirements ensure the minimum required emergency feedwater flow are achieved as described above."

Reason and Basis for Change: License Amendment No. 206 (ML16264A411) revised the EFW System Testing Requirements. The pump performance surveillance requirements (SR) were revised to conform more closely to the corresponding NUREG-1431, Revision 4, "Standard Technical Specifications Westinghouse Plants," (STS) requirements as applicable to VCSNS Unit 1. VCSNS revised TS 3/4.7.1.2 "Emergency Feedwater" to incorporate Westinghouse Standard Technical Specification surveillance frequency requirements for testing the MD and TD EFW pumps. Consistent with the STS, the SR interval was revised from at least every 31 days to "in accordance with the Inservice Testing Program." Also, consistent with the STS, the proposed surveillance specifies that "the developed head of each emergency feedwater pump

Document Control Desk RR 8925 RC-17-0139 Page 2 of 3 at the flow test point is greater than or equal to the required developed head" in place of specifying the pump head and flow values.

BRN No.17-004 Description of Change: TS Bases section 3/4.8.1, 3/4.8.2 and 3/4.8.3 A.C. Sources, D.C.

Sources and Onsite Power Distribution Systems," was revised to add the sentence, "In combination with other methods, Open Phase Isolation System (OPIS) is used to determine the availability of the preferred offsite source."

Engineering change ECR-50884, "OPC Strategy for 115kV GDC-17 Offsite Power Source,"

installed an independent OPIS in the monitoring mode on each of the station's three offsite power transformers that connect to GDC-17 offsite sources. Each OPIS is designed to detect open phase conditions as defined by Branch Technical Position (BTP 8-9, Revision 0) and to meet the intent of INPO Event Report IER L2 12-14, "Automatic Reactor Scram Resulting from a Design Vulnerability in the 4.16-kV Bus Undervoltage Protection Scheme," and NRC Bulletin 2012-01 (BL 2012-01), "Design Vulnerability in Electric Power System" for detecting an open phase condition.

Reason and Basis for Change: The change to the TS Bases sections 3/4.8.1, 3/4.8.2 and 3/4.8.3 was due to engineering change ECR-50884 installing the OPIS system in the alarm mode. The alarm mode is used to detect of an open phase condition and provide a trouble alarm for plant operators in the main control room. Adding the statement to the applicable TS Bases sections about OPIS updates the Bases by providing additional information on current plant configuration in regards to systems installed to detect an open phase condition.

The OPIS was designed and installed to detect open phase conditions as defined by Branch Technical Position (BTP 8-9, Revision 0) and to meet the intent of INPO Event Report IER L2 12-14, "Automatic Reactor Scram Resulting from a Design Vulnerability in the 4.16-kV Bus Undervoltage Protection Scheme," and NRC Bulletin 2012-01 (BL 2012-01), "Design Vulnerability in Electric Power System."

TS Amendment No. 209 Description of Change: Changes to the Bases for TS 3/4.3.1, "Reactor Trip System Instrumentation," and Bases 3/4.3.2, "Engineered Safety Feature Actuation System Instrumentation," were submitted and previously approved under License Amendment No. 209 (ML17206A412). The amendment revised the Bases to address implementation the Allowed Outage Time, Bypass Test Time, and Surveillance Frequency changes approved by the NRC in WCAP-15376-P-A, Rev. 1, "Risk-Informed Assessment of the Reactor Trip System (RTS) and Engineered Safety Features Actuation System (ESFAS) Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times." The changes in Amendment No. 209 were consistent with the approved Technical Specification Task Force (TSTF) Improved Standard Technical Specification Change Traveler TSTF-411, Revision 1, "Surveillance Test Interval Extensions for Components of the Reactor Protection System (WCAP-15376-P)."

Reason and Basis for Change: The paragraphs in TS Bases 3/4.3.1 and 3/4.3.2 needed to be updated to reflect changes to TS implemented under License Amendment No. 209. The amendment relaxed the allowed outage time, bypass test time, and surveillance test frequency for reactor protection system components. The changes were implemented based on guidance

Document Control Desk Attachment I RR 8925 RC-17-0139 Page 3 of 3 provided in WCAP-15376-P-A, Revision 1, "Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times" and the NRC approved Technical Specification Task Force (TSTF) Improved Standard Technical Specification Change Traveler TSTF-411, Revision 1, "Surveillance Test Interval Extensions for Components of the Reactor Protection System (WCAP-15376-P)."

Document Control Desk Attachment II RR 8925 RC-17-0139 Page 1 of 10 TECHNICAL SPECIFICATION BASES REVISIONS UPDATED THROUGH NOVEMBER 2017 Revision Notice #

Date Approved Pages Affected Amendment 207 01/18/17 B 3/4 5-3 BRN 17-002 05/23/17 B 3/4 7-2 BRN 17-004 05/23/17 B 3/4 8-1 Amendment 209 10/04/17 B 3/4 3-1 B 3/4 3-1 a B 3/4 3-1 b B 3/4 3-1c B 3/4 3-1 d B 3/4 3-1 e

EMERGENCY CORE COOLING SYSTEMS BASES REFUELING WATER STORAGE TANK (Continued)

The limits on contained water volume and boron concentration of the RWST also ensure a pH value of between 7.5 and 11.0 for the solution recirculated within containment after a LOCA.

This pH band minimizes the evolution of iodine and minimizes the effect of chloride and caustic stress corrosion on mechanical systems and components.

Alignment of the RWST to SF Purification has been designed with a safety related stand pipe, or riser loop seal, that is designed with sufficient elevation to maintain a required minimum TS volume per TS 3.5.4 LCO. A bypass line connecting the two legs of the riser loop was provided and contains a locked closed valve, XVA78094-SF, RWST Loop Seal Bypass Isolation Valve. This valve is locked closed in Modes 1 through 4 by administrative controls. The recirculation line is also locked closed at XVT06691-SF, Spent Fuel Cooling Purification Header Throttle Valve in Modes 1 through 4 by administrative controls. The SF Purification Loop returns to the RWST at an elevation higher than the RWST minimum TS volume.

SUMMER - UNIT 1 B 3/4 5-3 Corrected by letter dated 10/4/93, 192, 207

PLANT SYSTEMS BASES 3/4.7.1.2 EMERGENCY FEEDWATER SYSTEM The OPERABILITY of the emergency feedwater system ensures that the Reactor Coolant System can be cooled down to less than 350°F from normal operating conditions in the event of a total loss of off-site power.

Any two emergency feedwater pumps combined are capable of delivering a total feedwater flow of 380 gpm at a pressure of 1211 psig to the entrance of two out of three intact steam generators following a Main Feedwater Line Break event, while passively limiting the flow to the faulted steam generator. Automatic isolation of the faulted steam generator is not necessary to achieve this flow to the intact steam generators. The 380 gpm to the intact steam generators is sufficient to prevent over pressurization of the RCS and also to prevent the water in RCS hot leg from reaching a saturated condition. This capacity is sufficient to ensure that adequate feedwater flow is available to remove decay heat and reduce the Reactor Coolant System temperature to less than 350°F at which point the Residual Heat Removal System may be placed into operation.

Also, each Emergency Feedwater (EFW) pump is capable of supplying 400 gpm to all 3 steam generators while the steam generators are pressurized to 1211 psig. This capacity is sufficient to ensure that the pressurizer does not overfill during a loss of normal feedwater event. The minimum required pump head for the TD and MD pumps are controlled in accordance with the Inservice Testing Program as required by Specification 4.0.5. These minimum pump performance requirements ensure the minimum required EF flows are achieved, as described above.

3/4.7.1.3 CONDENSATE STORAGE TANK The OPERABILITY of the condensate storage tank with the minimum water volume ensures that sufficient water is available to maintain the RCS at HOT STANDBY conditions for 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> with steam discharge to the atmosphere concurrent with total loss of offsite power.

The contained water volume limit includes an allowance for water not usable because of tank discharge line location or other physical characteristics.

3/4.7.1.4 ACTIVITY The limitations on secondary system specific activity ensure that the resultant offsite radiation dose will be limited to a small fraction of 10 CFR Part 50.67 limits in the event of a steam line rupture. This dose also includes the effects of a coincident 1.0 GPM primary to secondary tube leak in the steam generator of the affected steam line. These values are consistent with the assumptions used in the accident analyses.

SUMMER - UNIT 1 B 3/4 7-2 Amendment No. 4-09r Corrected by Letter Dated 10M/93, 473, BRN 11 001, BRN 17-002

3/4.8 ELECTRICAL POWER SYSTEMS BASES 3/4.8.1. 3/4.8.2 AND 3/4.8.3 A.C. SOURCES. D.C. SOURCES AND QNSITE POWER DISTRIBUTION SYSTEMS The OPERABILITY of the A.C. and D.C power sources and associated distribution systems during operation ensures that sufficient power will be available to supply the safety related equipment required for 1) the safe shutdown of the facility and 2) the mitigation and control of accident conditions within the facility. In combination with other methods, Open Phase Isolation System (OPIS) is used to determine the availability of preferred off-site sources. The minimum specified independent and redundant A.C. and D.C. power sources and distribution systems satisfy the requirements of General Design Criterion 17 of Appendix "A" to 10 CFR 50.

The ACTION requirements specified for the levels of degradation of the power sources provide restriction upon continued facility operation commensurate with the level of degradation.

The OPERABILITY of the power sources are consistent with the initial condition assumptions of the safety analyses and are based upon maintaining at least one redundant set of onsite A.C. and D.C. power sources and associated distribution systems OPERABLE during accident conditions coincident with an assumed loss of offsite power and single failure of the other onsite A.C. source.

The A.C. and D.C. source allowable out-of-service times are based on Regulatory Guide 1.93, "Availability of Electrical Power Sources," December 1974. When one diesel generator is inoperable, there is an additional ACTION requirement to verify that all required systems, subsystems, trains, components and devices, that depend on the remaining OPERABLE diesel generator as a source of emergency power, are also OPERABLE, and that the steam-driven auxiliary feedwater pump is OPERABLE. This requirement is intended to provide assurance that a loss of offsite power event will not result in a complete loss of safety function of critical systems during the period one of the diesel generators is inoperable. The term verify as used in this context means to administratively check by examining logs or other information to determine if certain components are out-of-service for maintenance or other reasons. It does not mean to perform the surveillance requirements needed to demonstrate the OPERABILITY of the component.

The requirement for restoring the EDG to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> may be extended up to 14 days to perform either extended preplanned maintenance (both preventative and corrective) or extended unplanned corrective maintenance work.

To reduce the risk of performing extended EDG maintenance activities of up to 14 days while online, a non-safety related alternate AC power (AAC) source will be relied on. The AAC is designed to provide back-up power to either ESF bus whenever one of the EDGs is out of service, particularly in Modes 1 through 4 operation. The AAC is verified available and an operational readiness status check is performed when it is anticipated that one of the EDGs will be inoperable for longer than the allowed outage time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The design of the AAC is capable of providing the required safety and non-safety related loads in the event of a total loss of offsite power and if both EDGs fail to start and load. During these events it is assumed that there is no seismic event or an event that requires safeguards actuation, e.g., safety injection, containment spray, etc. Although the AAC is not designed for DBA loads, it is capable of supplying sufficient power to mitigate the effects of an accident. The AAC is not credited in the safety analysis.

The AAC consists of a minimum of three units at the Parr Hydro. A keep warm diesel generator is installed at Parr Hydro to provide for initial excitation and switching. For scheduled maintenance, Parr personnel will be at their workstations 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day. For unscheduled maintenance or an event, Parr personnel will have the units running within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of notification.

SUMMER - UNIT 1 B 3/4 8-1 Amendment No. 178 BRN 17-004

3/4.3 INSTRUMENTATION BASES 3/4.3.1 and 3/4.3.2 REACTOR TRIP AND ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION The OPERABILITY of the Reactor Protection System and Engineered Safety Feature Actuation System Instrumentation and interlocks ensure that 1) the associated action and/or reactor trip will be initiated when the parameter monitored by each channel or combination thereof reaches its setpoints, 2) the specified coincidence logic and sufficient redundancy is maintained to permit a channel to be out of service for testing or maintenance consistent with maintaining an appropriate level of reliability of the Reactor Protection and Engineered Safety Features instrumentation and, 3) sufficient system functions capability is available from diverse parameters.

The OPERABILITY of these systems is required to provide the overall reliability, redundancy, and diversity assumed available in the facility design for the protection and mitigation of accident and transient conditions. The integrated operation of each of these systems is consistent with the assumptions used in the accident analyses. The surveillance requirements specified for these systems ensure that the overall system functional capability is maintained comparable to the original design standards. The periodic surveillance tests performed at the minimum frequencies are sufficient to demonstrate this capability. Specified surveillance intervals have been determined in accordance with WCAP-10271, "Evaluation of Surveillance Frequencies and Out of Service Times for Reactor Protection Instrumentation System," and supplements to that report. Specified surveillance and maintenance outage times have been determined in accordance with WCAP-14333-P-A, Rev. 1, "Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," and Westinghouse letter CGE-05-46. Specified surveillance intervals and RTB outage times have been determined in accordance with WCAP-15376-P-A, Rev. 1, "Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times," dated March 2003. Surveillance intervals and out of service times were determined based on maintaining an appropriate level of reliability of the Reactor Protection System and Engineered Safety Features instrumentation. The Slave Relay Test is performed on an 18-month frequency that is specific to Westinghouse AR relays. This test frequency is based on relay reliability assessments presented in WCAP-13877-P-A, "Reliability Assessment of Westinghouse Type AR Relays Used as SSPS Slave Relays," that is dependent on the qualified life and environmental conditions of the AR relays. Replacement relays other than Westinghouse type AR or reconciled Cutler-Hammer relays will require further analysis and NRC approval.

Consistent with the requirement in Regulatory Guide 1.177 to include Tier 2 insights into the decision-making process before taking equipment out of service, restrictions on concurrent removal of certain equipment when a logic train is inoperable for maintenance are included (note that these restrictions do not apply when a logic train is being tested under the 4-hour bypass Note). Entry into Actions 12, 14, 21, or 25 is not a typical, pre-planned evolution during power operation, other than for surveillance testing. Since Actions 12, 14, 21, or 25 are typically entered due to equipment failure, it follows that some of the following restrictions may not be met at the time of entry into Actions 12, 14, 21, or 25. If this situation were to occur during the 24-hour AOT of Actions 12, 14, 21, or 25, the configuration risk assessment procedure will assess the emergent condition and direct activities to restore the inoperable logic train and exit Actions 12, 14, 21, or 25, or fully implement these restrictions, or perform a unit shutdown, as appropriate from a risk management perspective. The following restrictions will be observed:

• To preserve ATWS mitigation capability, activities that degrade the availability of the emergency feedwater system, RCS pressure relief system (pressurizer PORVs and safety valves), AMSAC, or turbine trip should not be scheduled when a logic train is inoperable for maintenance.

SUMMER - UNIT 1 B 3/4 3-1 Amendment No. 101, 177, 187, 209

INSTRUMENTATION BASES REACTOR TRIP AND ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION (continued)

• To preserve LOCA mitigation capability, one complete ECCS train that can be actuated automatically must be maintained when a logic train is inoperable for maintenance.

• To preserve reactor trip and safeguards actuation capability, activities that cause master relays or slave relays in the available train to be unavailable and activities that cause analog channels to be unavailable should not be scheduled when a logic train is inoperable for maintenance.

Activities on electrical systems (e.g., AC and DC power) and cooling systems (e.g.,

service water and component cooling water) that support the systems or functions listed in the first three bullets should not be scheduled when a logic train is inoperable for maintenance. That is, one complete train of a function that supports a complete train of a function noted above must be available.

Consistent with the NRC Safety Evaluation (SE) requirements in WCAP-15376-P-A, Rev. 1, Tier 2 insights must be included in the decision making process before removing an RTB train from service and implementing the extended (risk-informed) Completion Time for an RTB train. These "Tier 2 restrictions" are considered to be necessary to avoid risk significant plant configurations during the time an RTB train is inoperable.

Entry into Action 8 for an inoperable RTB train is not a typical, preplanned evolution during the MODES of Applicability for this equipment, other than when necessary for surveillance testing. Since Action 8 may be entered due to equipment failure, some of the Tier 2 restrictions discussed below may not be met at the time of Action 8 entry. In addition, it is possible that equipment failure may occur after the RTB train is removed from service for surveillance testing or planned maintenance, such that one or more of the required Tier 2 restrictions are no longer met. In cases of equipment failure, the programs and procedures in place to address the requirements of 10 CFR 50.65 (a) (4) require assessment of the emergent condition with appropriate actions taken to manage risk. Depending on the specific situation, these actions could include activities to restore the inoperable RTB train and exit the Action, or to fully implement the Tier 2 restrictions, or to perform a unit shutdown, as appropriate from a risk management perspective.

The following Tier 2 restrictions on concurrent removal of certain equipment will be implemented as described above when entering Action 8 when an RTB train is inoperable:

• The probability of failing to trip the reactor on demand will increase when a RTB is removed from service, therefore, systems designed for mitigating an ATWS event should be maintained available. RCS pressure relief (pressurizer PORVs and safety valves), emergency feedwater flow (for RCS heat removal), AMSAC, and turbine trip are important to ATWS mitigation. Therefore, activities that degrade the availability of the emergency feedwater system, RCS pressure relief system (pressurizer PORVs and safety valves), AMSAC, or turbine trip should not be scheduled when a RTB is inoperable.

SUMMER - UNIT 1 B 3/4 3-1 a Amendment No. 35, 120, 116, 177, 209

INSTRUMENTATION BASES REACTOR TRIP AND ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION (continued)

Due to the increased dependence on the available reactor trip train when one logic train is unavailable, activities that degrade other components of the RTS, including master relays or slave relays, and activities that cause analog channels to be unavailable should not be scheduled when a logic train is inoperable.

Activities on electrical systems (AC and DC power) that support the systems or functions listed in the first two bullets should not be scheduled when a RTB is inoperable.

The Engineered Safety Feature Actuation System Instrumentation Trip Setpoints specified in Table 3.3-4 are the nominal values at which the bistables are set for each functional unit. A setpoint is considered to be adjusted consistent with the nominal value when the "as measured" setpoint is within the band allowed for calibration accuracy.

To accommodate the instrument drift assumed to occur between operational tests and the accuracy to which setpoints can be measured and calibrated, Allowable Values for the setpoints have been specified in Table 3.3-4. Operation with setpoints less conservative than the Trip Setpoint but within the Allowable Value is acceptable since an allowance has been made in the safety analysis to accommodate this error.

The methodology to derive the trip setpoints is based upon combining all of the uncertainties in the channels. Inherent to the determination of the trip setpoints are the magnitudes of these channel uncertainties. Sensor and rack instrumentation utilized in these channels are expected to be capable of operating within the allowances of these uncertainty magnitudes. Rack drift in excess of the Allowable Value exhibits the behavior that the rack has not met its allowance. Being that there is a small statistical chance that this will happen, an infrequent excessive drift is expected. Rack or sensor drift, in excess of the allowance that is more than occasional, may be indicative of more serious problems and should warrant further investigation.

The measurement of response time at the specified frequencies provides assurance that the reactor trip and the engineered safety feature actuation associated with each channel is completed within the time limit assumed in the accident analyses. No credit was taken in the analyses for those channels with response times indicated as not applicable.

Response time may be demonstrated by any series of sequential, overlapping or total channel test measurements provided that such tests demonstrate the total channel response time as defined. Response time may be verified by actual response time tests in any series of sequential, overlapping, or total channel measurements, or by the summation of allocated sensor, signal processing, and actuation logic response times with actual response time tests on the remainder of the channel. Allocations for sensor response times may be obtained from: (1) historical records based on acceptable response time tests (hydraulic, noise or power interrupt tests), (2) in place, onsite, or offsite (e.g., vendor) test measurements, or (3) utilizing vendor engineering specifications. WCAP-13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements," provides the basis and methodology for using allocated sensor response times in the overall verification of the channel response time for specific sensors identified in the WCAP. Response time verification for other sensor types must be demonstrated by test.

SUMMER-UNIT 1 B 3/4 3-1 b Amendment No. 120, 146, 158, 177, 209

INSTRUMENTATION BASES REACTOR TRIP AND ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION (continued)

WCAP-14036-P-A, Revision 1, "Elimination of Periodic Response Time Tests,"

provides the basis and methodology for using allocated signal processing and actuation logic response times in the overall verification of the protection system channel response time.

The allocations for sensor, signal conditioning, and actuation logic response times must be verified prior to placing the component into operational service and re-verified following maintenance or modification that may adversely affect response time. In general, electrical repair work does not impact response time provided the parts used for the repair are of the same type and value. Specific components identified in the WCAP may be replaced without verification testing. One example where response time could be affected is replacing the sensing element of a transmitter.

Westinghouse letter CGE-00-018, dated March 28, 2000, provided an evaluation of the Group 05 (11NLP and 6NSA) 7300 process cards. These cards were revised after the submittal of WCAP-14036, Revision 1. This letter concluded that the failure modes and effects analysis (FMEA) performed for the older versions of these cards and documented in WCAP-14036-P-A, Revision 1, is applicable for these Group 05 cards. The bounding time response values determined by test and evaluation and reported in the WCAP are valid for these redesigned cards.

The Engineered Safety Features response times specified in Table 3.3-5 which include sequential operation of the RWST and VCT valves (Notes 2 and 3) are based on values assumed in the non-LOCA safety analyses. These analyses are for injection of borated water from the RWST. Injection of borated water is assumed not to occur until the VCT charging pump suction isolation valves are closed following opening of the RWST charging pumps suction valves. When the sequential operation of the RWST and VCT valves is not included in the response times (Note 1) the values specified are based on the LOCA analyses. The LOCA analyses take credit for injection flow regardless of the source.

Verification of the response times specified in Table 3.3-5 will assure that the assumptions used for the LOCA and non-LOCA analyses with respect to the operation of the VCT and RWST valves are valid.

The Engineered Safety Features Actuation System senses selected plant parameters and determines whether or not predetermined limits are being exceeded. If they are, the signals are combined into logic matrices sensitive to combinations indicative of various accidents, events, and transients. Once the required logic combination is completed, the system sends actuation signals to those engineered safety features components whose aggregate function best serves the requirements of the condition. As an example, the following actions may be initiated by the Engineered Safety Features Actuation System to mitigate the consequences of a steam line break or loss of coolant accident 1) safety injection pumps start and automatic valves position, 2) reactor trip, 3) feedwater isolation, 4) startup of the emergency diesel generators, 5) containment spray pumps start and automatic valves position, 6) containment isolation, 7) steam line isolation, 8) turbine trip, 9) auxiliary feedwater pumps start and automatic valves position, 10) containment cooling fans start and automatic valves position, 11) essential service water pumps start and automatic valves position, and 12) control room isolation and ventilation systems start.

SUMMER - UNIT 1 B 3/4 3-1c Amendment No. 67, 146, 158, 177, 209

INSTRUMENTATION BASES REACTOR TRIP AND ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION (continued)

Several automatic logic functions included in this specification are not necessary for Engineered Safety Feature System actuation but their functional capability at the specified setpoints enhances the overall reliability of the Engineered Safety Features functions. These automatic actuation systems are purge and exhaust isolation from high containment radioactivity, turbine trip and feedwater isolation from steam generator high-high water level, initiation of emergency feedwater on a trip of the main feedwater pumps, automatic transfer of the suctions of the emergency feedwater pumps to service water on low suction pressure, and automatic opening of the containment recirculation sump suction valves for the RFIR and spray pumps on low-low refueling water storage tank level.

The service water response time includes: 1) the start of the service water pumps and, 2) the service water pumps discharge valves (3116A,B,C-SW) stroking to the fully opened position. This condition of the valves assures that flow will become established through the component cooling water heat exchanger, diesel generator coolers, FIVAC chiller, and to the suction of the service water booster pumps when these components are placed in-service. Prior to this time, the flow is rapidly approaching required flow and sufficient pressure is developed as valves finish their stroke. Each of the above-listed components will be starting to perform their accident mitigation function, either directly or indirectly depending upon the use of the component, and will be operational within the service water response time of 71.5/81.5 seconds-. Only the service water booster pumps have a direct impact on the accident analysis via the RBCUs' heat removal capability as discussed below.

Total time is 1.5 second instrument response after setpoint is reached, plus 10 seconds diesel generator start, plus 10 seconds to reach service water pump start and begin 3116-SW opening via Engineered Safety Features Loading Sequencer, plus 60 seconds stroke time for 3116-SW. During this total time, the service water pumps start and the service water pump discharge valve begins to open at 11.5 seconds and the pump discharge valve is fully open at 71.5 seconds without a diesel generator start required and 21.5 seconds and 81.5 seconds including a diesel generator start.

SUMMER - UNIT 1 B 3/4 3-1d Amendment No. 67, 177, 209

INSTRUMENTATION BASES REACTOR TRIP AND ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION (continued)

The RBCU response time includes: 1) the start of the RBCU fan and the service water booster pumps and, 2) all the service water valves which must be driven to the fully opened or fully closed position. This condition of the valves allows the flow to become fully established through the RBCU. Prior to this time, the flow is rapidly approaching required flow as the valves finish their stroke. Although the RBCU would be removing heat through-out the Engineered Safety Features response time, the accident analysis does not assume heat removal capability from 0 to 71.5 seconds27 because the industrial cooling water system is not completely isolated until 71.5 seconds. A linear ramp increase from 95% full heat removal capability to 100% full heat removal capability is assumed by the accident analysis to start at 71.5 seconds and end at 86.5 seconds-. Full heat removal capability is assumed at 86.5 seconds based on the position of the valve 3107-SW.

The Engineered Safety Feature Actuation System interlocks perform the following functions:

P-4 Reactor tripped - Actuates turbine trip, closes main feedwater valves on Tavg below setpoint, prevents the opening of the main feedwater valves which were closed by a safety injection or high steam generator water level signal, allows safety injection block so that components can be reset or tripped.

Reactor not tripped - prevents manual block of safety injection.

P-11 On increasing pressurizer pressure, P-11 automatically reinstates safety injection actuation on low pressurizer pressure. On decreasing pressure, P-11 allows the manual block of safety injection actuation on low pressurizer pressure.

P-12 On increasing primary coolant loop temperature, P-12 automatically reinstates safety injection actuation and steam line isolation on low steam line pressure, and removes a blocking signal from the steam dump system. On decreasing primary coolant loop temperature, P-12 allows the manual block of safety injection actuation and steam line isolation on low steam line pressure and automatically provides a blocking signal to the steam dump system.

3/4.3.3 MONITORING INSTRUMENTATION 3/4.3.3.1 RADIATION MONITORING INSTRUMENTATION The OPERABILITY of the radiation monitoring channels ensures that 1) the radiation levels are continually measured in the areas served by the individual channels and 2) the alarm or automatic action is initiated when the radiation level trip setpoint is exceeded.

27 Total time is 1.5 second instrument response after setpoint Is reached, plus 10 second diesel start plus 60 seconds* for valves to isolate industrial cooling water system.

Total time is 1.5 second instrument response after setpoint is reached, plus 10 second diesel generator start plus 75 seconds to stroke valves 3107A, B-SW.

During this time period, the Engineered Safety Features Loading Sequencer starts the RBCU fans at 25 seconds and service water booster pumps at 30 seconds after the valves begin to stroke.

SUMMER - UNIT 1 B 3/4 3-1 e Amendment No. 67, 177, 209